This invention relates to coiled tubing systems used in wells, such as oil or gas wells. In particular, this invention relates to methods and apparatuses for determining the useful life and integrity of coiled tubing strings.
Coiled tubing may be introduced into an oil or gas well bore through wellhead control equipment to perform various tasks during the exploration, drilling, production, and workover of the well. Coiled tubing may be used, for example, to inject gas or other fluids into the well bore, to inflate or activate bridges and packers, to transport tools downhole such as logging tools, to perform remedial cementing and clean-out operations in the bore, to deliver drilling tools downhole, for electric wireline logging and perforating, drilling, wellbore cleanout, fishing, setting and retrieving tools, for displacing fluids, and for transmitting hydraulic power into the well. The flexible, lightweight nature of coiled tubing makes it particularly useful in deviated well bores.
Coiled tubing generally includes a small diameter cylindrical tubing made of metal or composite that has a relatively thin cross sectional thickness (e.g., from 0.067 to 0.203 inches (1.70-5.16 mm)). The continuous length of coiled tubing is a flexible product made from a steel strip. The strip is progressively formed into a tubular shape and a longitudinal seam weld is made by electric resistance welding (ERW) techniques. The product is typically several thousand feet long and is wound on a reel.
Conventional handling systems for coiled tubing can include a reel assembly, a gooseneck, and a tubing injector head. Reel assemblies may include a rotating reel for storing coiled tubing, a cradle for supporting the reel, a drive motor, and a rotary coupling. When the coiled tubing is introduced into a well bore, the tubing injector head draws the coiled tubing stored on the reel and injects the coiled tubing into a wellhead. The drive motor rotates the reel to pay out the coiled tubing and the gooseneck directs the coil tubing into the injector head. Often, fluids are pumped through the coiled tubing during operations. The rotary coupling provides an interface between the reel assembly and a fluid line from a pump.
During the injection process, coiled tubing is subjected to fatigue caused by “bending events” that may eventually lead to structural failure. At least three bending events may occur before newly manufactured coiled tubing even enters a well bore: unbending when the coiled tubing is first unspooled from the reel, bending when traveling over a gooseneck, and unbending upon entry into an injector. Bending the tubing creates severe flexural strains and plastic deformation of the tubing. For coiled tubing used in oil or gas wells, such plastic deformation can include strains typically within the range of about 0.01 to about 0.02, but can be higher depending on the coiled tubing size and bend radius utilized. Coiled tubing is also subjected to downhole stresses induced by friction between the coiled tubing and the well casing or well bore. Depending on the application, coiled tubing may also be subjected to internal and external pressure as fluids are pumped through the coiled tubing and/or as the coiled tubing is lowered to depths were hydrostatic fluid pressures are significant. Well bore environments may also be corrosive and subject to significant variations in temperature. An accumulation of bending events and other stresses can seriously undermine the integrity of coiled tubing.
To ensure that the coiled tubing does not fail during a wellbore operation, the coiled tubing is usually retired from service after only a few trips into a well bore. Software modeling may be used to estimate the fatigue life utilization of coiled tubing so as to get as much useful life out of the coiled tubing before it is retired. Modeling is used to determine when a coiled tubing should be taken out of service because of degradation brought about by the noted effects. Numerical models have been created to estimate how many cycles a particular type of coiled tubing can be used. Once an estimate has been determined, data is obtained when the coiled tubing is used so that the number of cycles of actual use can be known. However, this technique does not account for the specific condition of a particular coiled tubing or of all the environments in which it is used, other than possibly by way of some selected general adjustment factor (e.g., some factor assumed for a given corrosive environment).
Coiled tubing degradation is cumulative and ultimately leads to the point of catastrophic failure (complete breaking or severing) if the coiled tubing is used too long. Plasticity and fatigue models only estimate the actual condition of a particular coiled tubing string and must additionally include safety factors to insure that the coiled tubing string is retired from service before catastrophic failure occurs. However, premature retirement of the coiled tubing string results in economic losses. To avoid catastrophic failure, it is not uncommon for the coiled tubing to be removed from service at 50% of predicted life based on numerical model predictions. For example, if twenty-five 15,000 ft. coiled tubings are retired at 50% of their useful lives each year at a cost of $2/foot, the annual cost is $750,000. If the coiled tubings were not retired until 75% of useful life (i.e., a 50% increase over the foregoing example) had been expended, coiled tubing costs would be reduced (by $375,000 relative to the foregoing example) without increasing risk of catastrophic failure due to overextended use of the coiled tubing. Using the coiled tubing until nearly 100% of its useful life has been expended produces further savings.